FERC on Wednesday halted GridLiance Heartland’s entry into the MISO markets by blocking its $11.7 million purchase of six transmission lines from a Vistra Energy subsidiary (EC19-42).
The commission said GridLiance and the subsidiary, Electric Energy Inc. (EEI), failed to prove the acquisition wouldn’t adversely affect MISO rates. The deal involved two 161-kV substations and six 161-kV transmission lines that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets in question currently sit outside the MISO footprint.
The move would have marked GridLiance’s first foray into MISO, while increasing revenue requirement rates in the Ameren Illinois transmission pricing zone. GridLiance estimated it would incur $8.2 million a year to operate the lines, 8 to 10 miles in length, compared with EEI’s $4.6 million in costs. Once the transaction closed, GridLiance said it would transfer functional control of all six lines to MISO by 2022. The request was submitted to FERC late last year.
GridLiance and EEI claimed the increased rate requirement would be offset by the transaction’s benefits, including use of EEI’s existing interconnection with the Tennessee Valley Authority to ease the burden on MISO’s north-to-south constraint, elimination of some pancaked rates and the expansion of the RTO’s footprint by adding transmission that can import power from neighboring balancing authorities.
Paducah Gaseous Diffusion Plant | DOE
But the six lines, originally constructed for the sole purpose of powering the U.S. Energy Department’s now-defunct Paducah Gaseous Diffusion Plant uranium facility, aren’t exactly in high demand now, incumbent transmission owner Ameren argued. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area.
Ameren challenged GridLiance and EEI’s beneficial claims, arguing that no entities — except those already affiliated with EEI — have ever requested service over the lines in the last 25 years. Ameren also contended that neither GridLiance nor EEI undertook analysis to determine the likelihood of new transmission customers and pointed out that MISO already has interconnections to the TVA and LG&E/KU areas.
FERC agreed with Ameren, calling the supposed benefits “non-quantifiable” and unable to counteract an “admitted” increase in rates.
The commission also pointed to a GridLiance witness statement that “regardless of whether GridLiance Heartland purchases the EEI transmission facilities, those facilities will be placed into MISO’s functional control” because Vistra was already in the process of transitioning “several” units at the Joppa station into the RTO.
“We conclude that the benefits from integration of the transmission assets into MISO would occur irrespective of the proposed transaction,” FERC said.
While FERC wouldn’t speak to other factors regarding the merger because of the rate impact issue, it said its rejection was without prejudice and it invited the parties to file a revised acquisition proposal.
PJM’s incumbent transmission owners must sign designated entity agreements (DEAs) just the same as the nonincumbent developers building projects in their zones, FERC said Tuesday in an order denying rehearing on the issue.
The commission held firm to its position, explained in its original July 2018 ruling, PJM’s proposal to exempt incumbent TOs from signing DEAs because it would give them an undue advantage over non-incumbents (ER18-1647). (See FERC Rejects PJM Exemption for Incumbent TOs.)
It also rejected arguments by PJM and incumbents that the two groups of TOs were not “similarly situated” because each face different service mandates and penalties for falling short of those mandates.
“‘To say that entities are similarly situated does not mean that there are no differences between them; rather, it means that there are no differences that are material to the inquiry at hand,’” FERC said, quoting language in a separate February 2018 ruling involving NYISO TOs (ER15-2059-002, ER13-102-008). “Likewise, the courts have explained that entities are similarly situated if they are in the same position with respect to the ends that the law seeks to promote or the abuses that it seeks to prevent, even if they are different in many other respects.”
Construction of Ameren’s Illinois Rivers transmission line | Plocher Construction
FERC said that in past rulings it has held new and existing generators to the same standards for reactive power compensation, and equally applied transmission curtailments among non-federal renewable resources and federal hydroelectric and thermal services “because they all take firm transmission service.”
PJM and incumbent TOs requested rehearing in August 2018. Under current rules, both incumbent and nonincumbent TOs sign DEAs, which terminate once construction is complete. Nonincumbent TOs — competitive developers whose project proposals are selected by PJM through the FERC Order 1000 process — must also execute a consolidated transmission owners agreement (CTOA) before the prior contract can expire.
Notably, the commission said, breaching a DEA proves far easier and more expensive for nonincumbent TOs, which are subject to meeting construction milestones that may be delayed for reasons beyond their control. However, incumbent TOs only risk breaking the terms of a CTOA by missing scheduled in-service dates. Unlike incumbents, nonincumbent TOs must also “obtain a letter of credit or other financial instrument equal to 3% of the incremental project cost in the event of a breach,” meaning this extra cost must factor in project submissions, making the incumbent TO’s proposal cheaper by default.
The incumbent TOs “fail to recognize that the penalties for such noncompliance are not comparable to the upfront costs associated with the security requirement in the Designated Entity Agreement,” FERC wrote. “The penalty provisions of the Consolidated Transmission Owners Agreement are implicated only in the event of breach or other specified noncompliance, while the security requirement of the Designated Entity Agreement, as discussed above, necessarily increases a nonincumbent transmission developer’s costs. Further, due to the potential number and frequency of breach events, [the incumbent TOs’] comparison is inapt.”
FERC did accept PJM’s proposed Tariff revision that sets the time period for a transmission developer to accept its designation as a designated entity for 60 days after receiving an executable DEA, effective July 16, 2018.
FERC on Wednesday dismissed a second request from Linden VFT to rehear its order denying reconsideration of cost allocations for several PJM cross-seams projects (ER18-614).
The commission said Linden just rehashed its original rehearing request. The company also can’t offer new arguments unless the order it’s protesting changed the outcome of the proceeding, it said.
“The commission has explained that the successive rehearing of an order on rehearing lies only when the order on rehearing modifies the original order’s result in a manner that gives rise to a wholly new objection,” FERC wrote. “If it were otherwise, the commission would be faced with countless successive requests for rehearing as parties raised argument after argument, in search of a winner.”
| MISO
In June, the commission reaffirmed a July 2018 order that directed PJM and its transmission owners to submit compliance filings regarding cost responsibility assignments for four targeted market efficiency projects (TMEPs) with MISO.
In that order, Linden and Hudson Transmission Partners, each of which operates merchant lines into New York City and had recently converted its firm transmission withdrawal rights to non-firm, were ordered to partially pay for TMEPs b2971, b2973, b2974 and b2975 after FERC said existing Tariff language indicated the congestion benefits accruing to the lines justified subsequent cost responsibility. (See FERC Rejects PJM TMEP Rehearing Requests.) PJM TOs then submitted a compliance filing clarifying that TMEP allocations would be assigned to merchant facilities in the future too.
The New York Power Authority joined with Hudson and Linden in opposing the order, arguing that the Tariff “limits all cost allocations … based on their actual firm transmission withdrawal rights.”
In its second rehearing request submitted in July, Linden alone argued that TMEPs are a subset of required transmission enhancements, which carry associated charges that are “not to exceed the firm transmission withdrawal rights specified in the applicable interconnection service agreement.”
Linden also said FERC gave it no notice that it would impose costs once the merchant TO dropped the rights and argued that assigning the company cost responsibility for TMEPs from which it does not benefit conflicts with the commission’s cost-causation principle.
Texas power industry stakeholders grilled a member of NERC’s Board of Trustees during the Texas Reliability Entity’s quarterly meetings Tuesday.
Rob Manning, in just his second year on NERC’s board, was a special guest during Texas RE’s Members Representative Committee (MRC) and Board of Directors meetings in Austin, Texas. When conversation during the MRC meeting turned to NERC’s proposed merger of three technical committees, stakeholders took advantage of the opportunity to ensure ERCOT has enough of a voice before the agency. (See NERC Board Hears Debate over Committee Reorg.)
“I think it’s important, because ERCOT is very small. [It] doesn’t have the voting strength they do in the East and West,” said DeAnn Walker, chair of the Texas Public Utility Commission and a Texas RE director. “I’ll make every effort to be louder about it, because I have that capability. Maybe the reason we don’t sound loud to NERC is because we don’t have the problems they do in the East and [Western Electricity Coordinating Council].”
MRC Chair Liz Jones, an attorney for Oncor, said the composition of a working group to create a new Reliability and Security Council is “inherently biased to the East.”
“It’s not an issue to be remedied at an ad hoc committee level,” she said. “It’s an issue to be resolved at the NERC board.”
“Does it have to be written down, or can we agree?” Manning asked.
“It may be the lawyer in me, but words don’t last very long when they’re only spoken,” Jones replied.
Texas RE CEO W. Lane Lanford (left) and Director Lori Cobos, chief executive of the Texas Office of Public Utility Counsel | Texas RE
Manning said NERC wouldn’t get anything accomplished if it opened the decision-making to “everybody,” but he promised to share Jones’ concerns with the NERC working group.
“Once we come up with a plan and a process, we’ll put it out there for discussion,” he said.
“Everyone thinks they need to help us,” Walker said. “If they want to help us, they can let us be a part of the makeup of it.”
ERCOT spokesperson Leslie Sopko told ERO Insider that the grid operator is represented on several NERC committees. CEO Bill Magness is one of three ISO/RTO members of NERC’s Member Representatives Committee.
“Should changes occur to the existing NERC committee structure, ERCOT Inc., as well as market participants and stakeholders, would like to ensure the ERCOT region continues to be well represented,” Sopko said.
During the afternoon’s board meeting, Chair Fred Day ribbed Manning in announcing his presence as a “special guest.”
“After the MRC meeting, he feels that much more special,” Day said.
“The ERO machine is just the right thing we need to maintain reliability in North America,” Manning said. “It works. It works because of folks like you, keeping the train on the track and working properly.”
Human Error Causes 50% of Misoperations
Curtis Crews, Texas RE’s director of compliance assessments, briefed the board on the July 13 power outage in New York City, saying, “I don’t want anyone in this room to think it couldn’t happen here.”
MRC Chair Liz Jones (left) and Texas RE Director Curt Brockmann. | Texas RE
Pointing to Consolidated Edison’s recent explanation that the outage was caused by a misoperation on the distribution side, Crews said it appears there might not have been a violation of NERC standards. “Misoperation is not necessarily a violation,” he said.
Crews said the three largest causes of NERC misoperations last year were incorrect settings and design errors, relay failures and malfunctions, and communication failures. NERC has reported the same top three causes going back to 2014.
“Things happen out there,” he said, noting human error is responsible for about half of misoperations. “That human out there wiring to the wrong sensor.”
BP’s Ashby to Join Board of Directors
The board’s Nominating Committee said it would nominate former BP America Executive Vice President Crystal Ashby to one of four independent director positions. Ashby, who was last responsible for the company’s government and public affairs, will replace John Coughlin when his term expires at the end of the year.
The committee will also re-nominate Delores Etter to her independent position, effective Jan. 1, 2020. Etter and Ashby’s elections will be held in September.
The directors also approved revisions to the MRC election procedures for the Cooperative, Load Serving and Marketing, and Transmission and Distribution sectors, mirroring changes made by the Generation sector earlier this year. The changes address situations where there is a single vacancy for a sector’s primary representative to the MRC and remove language requiring a quorum during each round of balloting.
Pat Wood to Highlight Annual Meeting
Former FERC Chairman Pat Wood III will be the guest speaker at Texas RE’s annual membership meeting, to be held Dec. 11 at the organization’s conference center.
Wood also chaired the Texas PUC for six years. He has his own energy infrastructure development company, Wood3 Resources, and serves on three corporate boards: Dynegy, SunPower and Quanta Services.
Texas RE Hosts Japanese Professional
Kenta Takahashi, an associate director in the Japanese Ministry of Economy, Trade and Industry’s Space Industry Office, joined Manning as a special guest during Tuesday’s meetings. Takahashi is part of the Global Government-to-Government Partnership, a professional exchange program administered by the U.S. State Department in cooperation with Meridian International Center.
An electric industry-funded report on high-altitude electromagnetic pulses (HEMPs) underestimated the risks the grid faces and should not be used as the basis for mitigation, according to a critique released this week by a little-known group with ties to Maxwell Air Force Base.
In April, the Electric Power Research Institute (EPRI) released a study that concluded a HEMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. (See EMP Task Force Looks at Black Start, Nukes.)
Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | Electric Power Research Institute
A group calling itself the Electromagnetic Defense Task Force (EDTF) said almost 200 of its members — “military, government, academic and private industry experts in various areas of electromagnetic defense” — produced a critique of the EPRI report and concluded that relying on it would not address “remaining vulnerabilities impacting large power transformers, generating equipment, communication systems, data systems and microgrids designed for emergency backup power.”
“If U.S. government policymakers rely upon the methodology and conclusions of the EPRI report, effective high-altitude EMP protections will not be implemented, jeopardizing security of the U.S. electric grid and other interdependent infrastructures,” the group said in its 20-page report.
Randy Horton, EPRI’s EMP project manager and one of the authors of the April report, defended the work Wednesday. “EPRI stands behind our EMP research results and welcomes technical debates that are supported by science, facts and data,” he said in a statement. “Our conclusions were reached after three years of extensive laboratory testing and analysis of potential EMP impacts on the electric transmission system.”
Maps of the instantaneous geoelectric field magnitude of an E3 EMP at 20, 40 and 100 seconds | Electric Power Research Institute
An EPRI spokesman declined to elaborate or respond to specific criticisms, saying, “I think Randy’s quote lays out a good basis for further discussion.”
FERC declined to comment, and NERC and the Edison Electric Institute did not respond to requests for comment. Scott Backhaus, the Department of Homeland Security’s coordinator for EMP impacts on critical infrastructure, told ERO Insider on Thursday he is working on a response but that it is not complete.
EPRI’s report called for mitigation to protect the grid from the impacts of E-1 pulses — the first “hazard field” caused by an EMP, which lasts for about 2.5 nanoseconds. The second impact, an E2 EMP, lasts up to 10 milliseconds. The last hazard field, an E3, is marked by a very low frequency pulse that can last for hundreds of seconds. The event would be like a severe — albeit much shorter — geomagnetic disturbance (GMD) caused by solar flares.
EPRI acknowledged that its research was limited and did not include generation and distribution, saying it intended additional research on those subjects.
Scenario Choices
But the task force said EPRI also erred by not using realistic, worst-case scenarios in its analysis.
“Despite having access to defense-conservative Department of Defense threat scenarios, EPRI used alternative Department of Energy scenarios that assume adversaries would detonate nuclear weapons at nonoptimal altitudes, when the optimal altitudes are available in the open literature,” the report says.
The task force said a burst height of 75 km would produce the strongest E1 field strengths, but that EPRI used a height of 200 km, lowering the peak E1 field strength by almost two-thirds. Similarly, EPRI did not use the 150-km optimal burst height for peak E3 field strengths, choosing instead a height of 400 km.
The Electromagnetic Defense Task Force said EPRI did not use the 150-km optimal burst height for peak E3 EMP field strengths, choosing instead a height of 400 km. | Electromagnetic Defense Task Force, Metatech Corp.
“The methodology and findings of the EPRI report are not only markedly dissimilar from previous EMP studies, but in many cases entirely opposed to more than 60 years of prior DOD, government and contractor research and findings on EMP, system effects and hardening,” it said.
Russian and Chinese scientists have published research that calculated E1 impacts at least twice as great as those used in EPRI’s study, it said. “By avoiding the use of data from declassified Soviet EMP tests on the realistic E3 threat level, EPRI was able to minimize numerical estimates of damaged grid equipment, including hard-to-replace high-voltage transformers.”
“EPRI also assumed latitudes and longitudes for its detonation scenarios that are nonoptimal for producing maximum HEMP fields in the Northern Hemisphere,” EDTF said. EPRI assumed the detonation would be over the center of the U.S., not on the most populated portions of the country or the areas with most of the electric generation, the critique said.
Optimistic ‘in the Extreme’
The report says the digital protective relays (DPRs) on which EPRI focused its E1 research are more resilient than other grid elements such as substation communications and that EPRI suggested the relays would have a higher survival rate than previous peer-reviewed studies have found.
EPRI’s assessment of E1 HEMP impacts on voltage stability found that about 21,500 line terminals would be affected. Of the affected relays, EPRI assumed 1% of them would cause simultaneous tripping, which it said would cause the system to experience “perturbation” but “remain stable.”
“The EPRI report does not explain EPRI’s methodology of choosing just 1% of these relays, nor does it explain how EPRI can assume that the entire system will ‘remain stable’ when these relays are randomly tripped,” EDTF said.
Critics say a burst height of 75 km would produce the strongest E1 EMP field strengths, but that a study by EPRI used a height of 200 km, lowering the peak field strength by almost two-thirds. | Electromagnetic Defense Task Force, Metatech Corp.
EPRI did not assess how the failure of DPRs to prevent bus and transformer overloads or protect against over- and under-frequency and over- and under-voltage conditions would affect the grid, EDTF said.
EPRI also assumed that attackers would deploy only a single nuclear weapon in a HEMP attack, ignoring the risk of multiple HEMPS, according to EDTF.
“Protective relay damage and associated line terminal loss from realistic HEMP scenarios could be far greater, especially with a multiple-bomb EMP attack. Relay malfunction during a HEMP attack would likely cause other electric grid systems to fail, resulting in large-scale cascading blackouts and widespread equipment damage. Notably, E1 effects on protective relays are likely to interrupt substation self-protection processes needed to interrupt E3 current flow through transformers,” EDTF said.
“An initial HEMP attack could render a number of relays inoperable, causing grid debilitation due to the loss of transformer isolation, fault protection, and islanding capabilities. Thus, a follow-on HEMP attack on a grid with a portion of damaged or disrupted DPRs would likely cause increased and catastrophic equipment damage from flashovers, uninterrupted overloads, faults and cascading events resulting in a wider-scale and longer-duration blackout. Also, a second HEMP attack after damaged DPRs are replaced could eliminate the ability to recover due to depletion of DPR spare inventories.”
The EDTF noted that “large-scale grid blackouts have occurred in the past from single-point failures, such as the Northeast Blackout of 2003, which was caused by overgrown trees contacting electric transmission lines.”
The blackout affected more than 70,000 MW of load, leaving 50 million people without electricity. “In contrast, EPRI’s report concludes that a HEMP attack on the same Eastern Interconnection would cause limited regional voltage collapses and affect roughly 40% of the electrical load lost in the 2003 blackout. Experience with cascading collapse in the Eastern Interconnection shows EPRI’s finding to be optimistic in the extreme.”
Authors’ Identity Shielded
EDTF said its critique was the work of attendees of the group’s second “summit” in May under “Chatham House Rules,” in which they contributed without attribution. “The experts who contributed to this specific document range from uniformed military personnel, to civil servants throughout a range of government agencies and various national laboratories, to internationally renowned and published engineers.”
The critique was circulated by the Foundation for Resilient Societies and published on the website of Over the Horizon, which describes itself as “a digital journal that brings together disparate perspectives to advance the conversation on the emerging security environment.”
Thomas Popik, president of the Foundation for Resilient Societies | Harvard Business School
Resilient Societies President Thomas S. Popik, a former Air Force captain who attended the EDTF summit, said in an interview that the critique “has a firm scientific basis.”
The EDTF published the names of more than 100 organizations it said were represented at the summit, including DHS, FERC, the Joint Chiefs of Staff, NASA and several units of the Air Force. The only individual named in the critique is Air Force Maj. David Stuckenberg, who did not respond to requests for comment.
The Air Force also did not respond to questions about its relationship with the EDTF. The task force has a webpage on the Maxwell Air Force Base website, and its 2018 report is published on the website of the base’s Air University and included in the Homeland Security Digital Library. The 2018 report lists as authors Stuckenberg, former Navy Secretary and CIA Director R. James Woolsey Jr., and Air Force Col. Douglas DeMaio, who gave a presentation to the NERC EMP Task Force in July. (See Air Force: US Must Take ‘Higher Ground’ in Space.)
Popik said he wasn’t certain if Resilient Societies is part of the EDTF. “I know that we were invited to the meeting, so that would imply we’re part of the task force, but the actual conditions for membership in the task force are… I think it would be best if you ask that question of Maj. Stuckenberg.”
Incentives and Motives
EDTF said it “operates on the military’s premise of planning for the reasonable upper-bound scenarios and validating results through real-world testing.” EDTF said EPRI’s report might dissuade transmission owners and operators from mitigating EMP risks or planning for post-HEMP grid restoration. “Some EDTF personnel working on HEMP-mitigation efforts alongside electric industry partners have lost both momentum and the interest of their industry partners,” it said.
Popik praised NERC for including him as the only non-industry member of its EMP Task Force. “That’s been an open and transparent process, which is coming to a solid proposal for a process to address the executive order,” he said. “It really is very important to distinguish the work of the EMP Task Force at NERC from the efforts of the Department of Homeland Security and EPRI and [the] Department of Energy in regard to this study of EMP effects.”
He cited DHS’ Backhaus, who told the NERC task force in June that they should “use physics and engineering to constrain our analysis” and avoid overestimating the risk. “EMP is one of many threats, so we need to develop our best estimate of risk from EMPs and GMDs to place them in context of the other risks that the bulk system faces,” Backhaus said. (See EMP Task Force Takes ‘First Bite of the Elephant’.)
Popik said utilities “without a ready means for cost recovery [and] faced with the potential of a very expensive grid security standard … would have ample incentive to make sure the EMP threat was not — you can put this in quotes — ‘overestimated.’”
“… When you try and use the so-called best available science and physics and engineering to … avoid a conclusion that would be in conflict with a regulatory agenda, that’s not good science.”
ERCOT‘s Technical Advisory Committee last week endorsed three additional “foundational pieces” to real-time co-optimization (RTC), the market tool being designed to procure energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.
TAC members unanimously approved the key principles in an email vote following an Aug. 28 briefing by ISO staff. The briefing was held in lieu of the committee’s regularly scheduled meeting to help the task force drafting RTC key principles stay on track.
“We want to harden [the principles] and move on. We don’t want to be like nodal and do it over again,” said ERCOT’s Matt Mereness, who chairs the Real-Time Co-Optimization Task Force (RTCTF), referencing the cumbersome effort to design and implement the grid operator’s nodal market.
“I didn’t think we needed to spend a whole meeting on this,” said TAC Chair Bob Helton, of ENGIE.
The key principles (KPs) reviewed by the TAC were:
KP 1.4 will modify the systems and applications that provide input for the current real-time market (RTM) optimization engine to accommodate the awarding of AS in real time. AS will be a resource specific award, and regulation instructions will be generation resource-specific.
KP 1.5 will modify processes for deploying AS to accommodate real-time awards. The principle will look at systems and communications between ERCOT and qualified scheduling entities in dispatching and deploying AS.
KP 3 will modify the reliability unit commitment (RUC) process to be consistent with how energy and AS will be awarded in the RTM. RUC will review resources scheduled to be available to determine whether additional resource commitments are needed to meet the load forecast and minimum AS requirements and resolve transmission congestion under defined penalty curves and factors.
The TAC held an email vote following the online session to endorse the principles. Members have until Aug. 30 to send in their votes.
The Texas Public Utility Commission directed ERCOT to add RTC to its market. The grid operator has estimated it will take four or five years and at least $40 million to modify its market, but its Independent Market Monitor says the grid operator could save as much as $400 million annually in reduced congestion costs and AS costs. (See PUCT Continues Review of Potential Market Improvements.)
The task force faces a February deadline to complete 13 key principles. It is currently working on AS demand curves and an offer structure, and it has begun discussions on changes to the day-ahead market.
The task force next meets Sept. 19 and Sept. 24. The latter meeting includes a half-day lessons-learned session with MISO, PJM and SPP representatives.
PORTLAND, Ore. — Just as the Western Energy Imbalance Market’s Governing Body was poised to fill the empty space within its ranks, another vacancy immediately popped up.
The EIM Governing Body voted Wednesday to fill the seat vacated by one of its original members — but not before revealing that its newest member had also resigned his position the night before.
Member Travis Kavulla was notably — but not surprisingly — absent from the body’s monthly meeting in downtown Portland. After all, his wife had just recently given birth, Governing Body Chair Carl Linvill told a hotel conference room packed with regional stakeholders.
But Linvill then delivered unexpected news: “We received a letter from Travis that he has been offered an opportunity which he plans to accept, which will mean that he will no longer serve — effective immediately — on the EIM Governing Body.”
Kavulla, a former member of the Montana Public Service Commission, was elected to the Governing Body in June 2018 after being term-limited out of his commission seat. (See CAISO Board Approves More CRR Auction Changes.) He currently serves as the energy director for R Street Institute, a D.C.-based think-tank that advocates for “free markets and limited, effective government.”
Kavulla, who joined R Street last October, shared his resignation letter to the EIM but told RTO Insider, “I’m not in a position to make any announcements at the moment.” The letter said he had accepted a job with a “market participant” and would be starting work next month.
Kavulla’s term as a Governing Body member was set to expire in 2021. His resignation marks the second premature departure from the body since April, when Kristine Schmidt, the group’s inaugural chair, vacated her seat to join the board of embattled PG&E Corp. Allowing Schmidt to hold both positions would have presented a conflict of interest, then-Chair Valerie Fong said at the time. (See PG&E Departure Leaves EIM Vacancy.)
To replace Schmidt, the body on Wednesday confirmed Anita Decker, a familiar name to industry participants in the Pacific Northwest.
From 2014 until earlier this year, Decker served as executive director of the Northwest Public Power Association, an advocacy group representing about 150 community-owned electric utilities in nine Western states and British Columbia. She was chief operating officer of the Bonneville Power Administration from 2007 to 2014, when she also performed a stint as acting administrator for the Western Area Power Administration. Prior to that, Decker had a 27-year career with PacifiCorp, where she rose to the position of a business unit vice president, having worked for the utility in Oregon, Wyoming and Utah.
“We had an incredibly qualified pool of candidates this year,” said EIM Nominating Committee Chair Jennifer Gardner, a senior attorney with Western Resource Advocates. Gardner described the deliberations leading to the nomination of Decker as being “consensus-driven,” bringing together representatives from the EIM’s various sectors in a “time-intensive process.” In addition to seeking someone with subject matter expertise, the committee put a high priority on experience in the West, with a focus on geographic diversity, she said.
“It was a difficult decision because we had some very qualified candidates, which I think speaks well to the Energy Imbalance Market in general,” member John Prescott said. “There’s a lot of interest out there from very qualified people that would like to serve on this Governing Body.”
Decker’s term will run from Sept. 1 until June 30, 2020, when Schmidt’s term was set to expire.
Not ‘Discretionary’
After the Governing Body’s three remaining members voted unanimously to confirm Decker, Fong quickly posed the question of whether the body should prompt the Nominating Committee to begin searching for Kavulla’s replacement.
“That’s technically not on the agenda,” said CAISO Senior Counsel Greg Fisher, who was sitting with the EIM leaders.
“Is it actually an action item? It’s just a recommendation that they move forward,” Fong said.
Fisher advised against proceeding so informally, saying the matter was not “discretionary” for the Governing Body, given the amount of time left before the expiration of Kavulla’s term, which leaves uncertain the process for replacing him.
“So, we’ll wait to hear back with a formal opinion from you on that and we’ll proceed,” Linvill confirmed.
Speaking to RTO Insider about Kavulla’s resignation after the meeting, Linvill said, “We’ll miss his contributions. He was an important member of the Governing Body — and we’ll leave it to him to announce what his plans are.”
“Travis is a big loss. He brings a wealth of expertise to the Governing Body,” Gardner said. But having recently vetted the list of industry hopefuls seeking to take over for Schmidt, she was optimistic about finding yet another replacement.
“I think a lot of folks have an interest in seeing the EIM succeed. I have no doubt we’ll have an excellent pool of candidates.”
MISO and PJM said Tuesday they will propose changes to how they determine flowgate rights in a white paper in November.
The RTOs use an April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before the creation of their seam. That date is used to determine both firm flow entitlements (FFEs) used in market-to-market settlements and firm flow limits (FFLs) used in transmission loading relief (TLR).
Earlier in August, MISO staff said the RTOs were considering filing a freeze date solution that would almost certainly be opposed by nonmarket parties to the congestion management process, leaving a decision up to FERC.
During a Joint and Common Market conference call, however, the RTOs said they hope they will be able to find an agreement with the nonmarket parties — including SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. — by November. (See Outside Parties Slow MISO-PJM Freeze Date Thaw.)
PJM and MISO footprints | MISO, PJM
MISO and PJM’s proposed solution would divide flowgate rights by age, with priority to network resources from 2004 and earlier, followed by: network resources from 2004 or later; transfers between local balancing authorities to make up shortages on a pro rata basis; and RTO load served by RTO dispatch — in that order.
“Of course, the current freeze date process is not suitable for markets right now. … Of course, the solution will increase transfer rights for markets over nonmarket entities. That’s been a big concern for the nonmarket,” Andy Witmeier, of MISO’s seams administration team, said earlier in August. Witmeier said nonmarket neighbors of the RTOs are concerned that their reliability may be impacted by a decrease in non-firm transfer availability. They also fear that an increase in firm limits for post-2004 network resources could lead to more curtailments of non-firm transfers for those outside the two markets.
Witmeier had said MISO and PJM could either file the freeze date changes with changes only to the RTOs’ FFEs, leaving FFLs alone. But MISO staff said they would prefer a full solution that includes FFLs or to file a contested solution and let FERC decide.
The white paper will discuss the solution only as it applies to FFEs. Joe Rushing, of PJM’s interregional market relations team, said Tuesday that the RTOs will continue to discuss with neighboring balancing authorities how FFLs can be updated from the freeze date.
Rushing said the RTOs may consider creating a market mechanism to cut a portion of firm market flows when curtailment of nonmarket flows doesn’t provide enough relief to avoid TLRs. He also said they plan to study individual flowgates to figure out if some might be overtaxed.
He promised more discussion on the issue at the JCM meeting Nov. 19, when the RTOs expect to unveil the white paper.
No MISO Guarantee on PJM Customers’ Revenue Rights
Meanwhile, the RTOs have conceded there is no way for MISO to guarantee PJM’s customer-funded incremental auction revenue rights (IARRs) will result in a corresponding increase in FFEs.
However, the RTOs are promising more accurate estimates of increased flowgate entitlements when an IARR requires a joint coordinated study on the transmission upgrade.
Rushing said the grid operators have received little stakeholder comment on the small potential for financial risks to PJM members.
Both RTOs offer IARRs, which reflect upgrades that increase capability on their transmission facilities. IARR megawatts are awarded for the additional capability created for the life of the upgrade or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices. However, PJM’s process provides an additional option that allows a specified IARR to be awarded when a customer agrees to fund transmission upgrades necessary to support the new auction revenue rights request. PJM is also obligated to guarantee at least 80% of IARR megawatts. (See PJM, MISO Plan Study to Coordinate Incremental ARRs.)
MISO has repeatedly said it cannot make guarantees on future FFE allocations to PJM members. PJM staff have said it’s possible they won’t be able to guarantee the 80% share if transmission upgrades affect the MISO system.
The federal judge overseeing PG&E’s bankruptcy relinquished a major part of the case dealing with wildfire damages to another federal judge while a third part of the case is heading to state court for resolution.
U.S. Bankruptcy Judge Dennis Montali said he understood the divided process is awkward, but he wanted to speed up the case and protect the rights of fire victims.
He decided a federal district court judge, not a bankruptcy judge, should estimate the wildfire damages, which are a key component of the utility’s bankruptcy.
Some parties have suggested PG&E might be required to pay $10 billion to $40 billion to victims of the wildfires that scorched Northern California in the past two years.
“I felt compelled to toss the ball to the district court,” Montali told lawyers during a bankruptcy hearing Tuesday. The judge said he would be doing a disservice to victims to try to rush through the complex and unusual proceeding while attending to the rest of the massive bankruptcy case.
Phyllis J. Hamilton, chief judge for the Northern District of California, approved Montali’s request to assign the estimation proceeding to a trial judge. District Court Judge James Donato, whose courtroom is in the same building as Montali’s, will now hear the matter.
Montali said the state Legislature’s July passage of AB 1054 had increased the pressure to resolve PG&E’s bankruptcy more quickly. The law allows PG&E to share in a $21 billion wildfire damages fund administered by the state but only if it exits bankruptcy by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
“While that may seem a long way in the future, and no doubt is far too long for thousands of victims, the complexity of these Chapter 11 cases, the requirements of Chapter 11 and the need for parallel hearings and rulings by the California Public Utilities Commission — most of which pertain to regulatory matters and contractual obligations that exist apart from the wildfire claims — impose very difficult time limits on all parties, including the court,” the judge wrote.
A CPUC attorney told the judge Tuesday the commission would need time to weigh the effects of a reorganization plan on ratepayers and PG&E’s financial stability.
Earlier this month, Montali agreed to allow claims against PG&E over the October 2017 Tubbs Fire to be decided in state court.
The Tubbs Fire, which killed 22 people, destroyed more than 5,600 structures and leveled a section of Santa Rosa, Calif., was the most destructive in state history until the Camp Fire in November 2018 killed 86 people and burned 18,804 structures, destroying most of the town of Paradise.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) blamed the Camp Fire on a faulty PG&E transmission line but said the Tubbs Fire was caused by shoddy wiring on private property.
Plaintiffs’ lawyers still want a judge or jury to decide PG&E’s liability for the Tubbs Fire, however, and Montali agreed on Aug. 16 to lift a stay on legal actions against the company and allow the matter to go to state court on an expedited basis. (See Only PG&E Can File Bankruptcy Plan, Judge Says.)
PG&E has said it plans to file a reorganization plan by Sept. 9, but that plan can’t be finalized without a better idea of the damages from the Camp Fire, the Tubbs Fire and a rash of other fires in October 2017, most of which have been blamed on PG&E equipment.
The utility has indicated it wants to establish a “capped fund” to pay wildfire victims, but Montali said he needs to know where to set the cap before approving a compensation fund.
FERC ordered paper hearings Monday in disputes over the criteria PJM used to reject several hydroelectric resources from pseudo-tying into the RTO’s grid.
Both Brookfield Energy Marketing and Cube Yadkin Generation said PJM erred when it determined some of their generating resources didn’t meet the RTO’s pseudo-tie requirements, preventing the companies from offering capacity.
Brookfield Complaint
In January, Brookfield challenged PJM’s assertion its Calderwood and Cheoah generating facilities did not pass the market-to-market flowgate test or meet its extraterritorial deliverability requirements, despite maintaining a firm point-to-point service from the Tennessee Valley Authority into Duke Energy’s balancing authority area at an annual cost of $5 million. The company says it has held capacity obligations in PJM since 2014.
PJM told Brookfield in March 2018 its tests determined the facilities failed for 38 flowgates. A follow-up test three months later found the facilities failed “19 transmission elements.” PJM rejected as insufficient a report prepared by Quanta Technology that affirmed Brookfield’s point-to-point service complies with the RTO’s requirements.
Brookfield Energy Marketing’s Calderwood Dam is on the Little Tennessee River in Blount County, Tenn.
PJM’s current pseudo-tie rules were approved by the commission in November 2017. The order included a five-year transition period for resources that had an existing pseudo-tie and had cleared in a capacity auction before May 2017 (ER17-1138). As a result of the failed tests, PJM said the Brookfield generators would be ineligible to participate in its capacity auction for the 2022/23 delivery year, after the transition period expired.
FERC ruled Aug. 26 that Brookfield’s complaint raised legitimate concerns about how PJM applied its requirements (EL19–34). The commission noted PJM’s Tariff and Manuals do not specify the “deliverability criteria” the RTO uses for its evaluations.
“The record is not clear as to what deliverability criteria PJM uses to determine whether pseudo-tied resources can participate in the auctions, whether it uses those deliverability criteria consistently for all projects or how PJM evaluated the Brookfield facilities,” the commission said. ” … PJM has not sufficiently explained why the Brookfield facilities failed the M2M flowgate test while other external generators affecting the same flowgate (Flowgate No. 93209) did not.”
However, the commission denied Brookfield’s request to extend the five-year transition period. PJM said doing so would be inappropriate because the transition period is memorialized in the Tariff and would require a showing that the original transition was unjust and unreasonable. “Brookfield has presented neither a basis on which the commission could grant its requested interim relief nor a demonstration such relief would be appropriate in these circumstances,” FERC said.
Cube Yadkin Complaint
Cube Yadkin Generation filed its complaint after PJM informed it in June 2018 that its 220-MW Yadkin Project — the Tuckertown, High Rock, Falls and Narrows hydroelectric sites on the Yadkin River about 75 miles from Charlotte, N.C. — did not meet the “electrical distance” requirement under its pseudo-tie rules.
FERC approved the electrical distance test in its 2017 order, saying it struck an appropriate balance between allowing external resources to participate in PJM’s capacity market while providing the RTO with reliability assurance. The commission said it accepted PJM’s representation that the further its state estimator model extends beyond its own borders, the less resilient the PJM system becomes to data losses and inaccuracies.
Yadkin River hydro project | Cube Yadkin Generation
In its Aug. 26, order, the commission said Yadkin had raised factual questions about how PJM conducted the electrical distance test (EL19-51). Cube Yadkin said PJM’s identification of three electrically closest buses for the project is electrically impossible because the series arrangement of the resources — with grid connections to only High Rock and Badin — means there can only be two closest buses.
FERC said PJM did not directly dispute Cube Yadkin’s arguments but responded each site’s location has a “unique set of paths through and out of the Yadkin area to the PJM border and, given these unique paths, finding differences between each location is not unexpected.”
The commission said that raised questions as to how PJM’s algorithm selects the buses and paths used in the electrical distance test and whether the selection of the wrong bus could cause a generator to fail when it would have otherwise passed.
FERC gave PJM 30 days to respond to its questions about its methodology, with responses by Brookfield and Yadkin due within 15 days of the RTO’s filings. “After receipt of these filings, commission staff is authorized to establish additional procedures, including a staff technical conference,” FERC said.
